Note: Descriptions are shown in the official language in which they were submitted.
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METHODS AND SYSTEMS FOR PROVIDING STEAM
FIELD
[0001] The present techniques provide methods for generating steam. More
.. specifically, the techniques provide methods and systems for adapting steam
generation to hydrocarbon recovery processes.
BACKGROUND
[0002] This section is intended to introduce various aspects of the art,
which may be
associated with exemplary embodiments of the present techniques. This
discussion is
believed to assist in providing a framework to facilitate a better
understanding of
particular aspects of the present techniques. Accordingly, it should be
understood that
this section should be read in this light, and not necessarily as admissions
of prior art.
[0003] Modern society is greatly dependant on the use of hydrocarbons
for fuels and
chemical feedstocks. Hydrocarbons are often found in subsurface rock
formations that
can be termed "reservoirs." Removing hydrocarbons from the reservoirs depends
on
numerous physical properties of the rock formations, such as the permeability
of the
rock containing the hydrocarbons, the ability of the hydrocarbons to flow
through the
rock formations, and the proportion of hydrocarbons present, among others.
[0004] Easily harvested sources of hydrocarbon are dwindling, leaving less
accessible sources to satisfy future energy needs. However, as the costs of
hydrocarbons increase, these less accessible sources become more economically
attractive. For example, the harvesting of oil sands to remove hydrocarbons
has
become more extensive as it has become more economical. The hydrocarbons
.. harvested from these reservoirs may have relatively high viscosities, for
example,
ranging from 8 API, or lower, up to 20 API, or higher. Accordingly, the
hydrocarbons
may include heavy oils, bitumen, or other carbonaceous materials, collectively
referred
to herein as "heavy oil," which are difficult to recover using standard
techniques.
[0005] Several methods have been developed to remove hydrocarbons from
oil
sands. For example, strip or surface mining may be performed to access the oil
sands,
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which can then be treated with hot water or steam to extract the oil. However,
deeper
formations may not be accessible using a strip mining approach. For these
formations,
a well can be drilled to the reservoir and steam, hot air, solvents, or
combinations
thereof, can be injected to release the hydrocarbons. The released
hydrocarbons may
then be collected by the injection well or by other wells and brought to the
surface.
[0006] A number of techniques have been developed for harvesting heavy
oil from
subsurface formations using thermal recovery techniques. Thermal recovery
operations
are used around the world to recover liquid hydrocarbons from both sandstone
and
carbonate reservoirs. These operations include a suite of steam based in situ
thermal
recovery techniques, such as cyclic steam stimulation (CSS), steam flooding
and steam
assisted gravity drainage (SAGD) as well as surface mining and their
associated
thermal based surface extraction techniques.
[0007] For example, CSS techniques includes a number of enhanced
recovery
methods for harvesting heavy oil from formations that use steam heat to lower
the
viscosity of the heavy oil. The CSS process raises the steam injection
pressure above
the formation fracturing pressure to create fractures within the formation and
enhance
the surface area access of the steam to the heavy oil. The steam raises the
temperature of the heavy oil during a heat soak phase, lowering the viscosity
of the
heavy oil. The injection well may then be used to produce heavy oil from the
formation.
The cycle is often repeated until the cost of injecting steam becomes
uneconomical, for
instance if the cost is higher than the money made from producing the heavy
oil.
However, successive steam injection cycles may reenter earlier created
fractures and,
thus, the process becomes less efficient over time.
[0008] Solvents may be used in combination with steam in CSS processes,
such as
in mixtures with the steam or in alternate injections between steam
injections. After
injection with the steam, the liquid hydrocarbons are transported as vapors to
contact
heavy oil surrounding steamed areas between adjacent wells. The injected
hydrocarbons can be produced as a mixture with the heavy oil phase. The
loading of
the liquid hydrocarbons injected with the steam can be chosen based on
pressure
drawdown and fluid removal from the reservoir using lift equipment in place
for the CSS.
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[0009] Another group of techniques is based on a continuous injection of
steam
through a first well to lower the viscosity of heavy oils and a continuous
production of
the heavy oil from a lower-lying second well. Such techniques may be termed
"steam
assisted gravity drainage" or SAGD. In SAGD, two horizontal wells are
completed into
the reservoir. These wells can be started as slant wells at surface or
vertical wells and
drilled to different depths within the reservoir. Thereafter, using
directional drilling
technology, the two wells are extended in the horizontal direction that result
in two
horizontal wells, vertically spaced from, but otherwise vertically aligned
with the other.
Ideally, the production well is located above the base of the reservoir but as
close as
practical to the bottom of the reservoir, and the injection well is located
vertically 10 to
30 feet (3 to 10 meters) above the horizontal well used for production.
[0010] The upper horizontal well is utilized as an injection well and is
supplied with
steam from the surface. The steam rises from the injection well, permeating
the
reservoir to form a vapor chamber that grows over time towards the top of the
reservoir.
.. The steam, and its condensate, raise the temperature of the reservoir and
consequently
reduce the viscosity of the heavy oil in the reservoir. The heavy oil and
condensed
steam will then drain downward through the reservoir under the action of
gravity and
may flow into the lower production well, whereby these liquids can be pumped
to the
surface. At the surface, the condensed steam and heavy oil are separated, and
the
heavy oil may be diluted with appropriate light hydrocarbons for transport by
pipeline.
[0011] As a result of the unique wellbore configuration in SAGD, any
condensate,
e.g., any liquid water phase, injected into the reservoir with the steam will
fall directly to
the underlying production well due to the influence of gravity, and thereby
not contribute
to the recovery of the hydrocarbons. For this reason, the current convention
in SAGD
projects is to separate the condensate from a wet steam flow and inject the
dry steam
phase into the injection wells used in the recovery process. As used herein,
wet steam
is a flow of steam that holds entrained water droplets originating either from
incomplete
conversion of a water stream into steam or from condensation of the steam. The
steam
after the condensate has been removed is referred to as dry steam.
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[0012] As discussed above, SAGD is a process where the recovery process
benefits
from the injection of dry steam. In contrast, CSS, steamflooding and SAGD
infill well
injectors are examples of processes that make thermally efficient use of wet
steam
which can also be demonstrated using numerical simulation.
[0013] The vast majority of the commercial thermal recovery schemes produce
steam for injection activities through once-through-steam-generators (OTSG) or
cogeneration facilities that utilize heat-recovery-steam-generators (HRSG). A
common
feature of OTSGs and HRSGs is that the steam is generated inside a series of
boiler
tubes that are heated by combustion of a hydrocarbon fuel external to the
boiler tubes.
As a result of the application of this external heat source a progressively
larger fraction
of the water inside the boiler tubes is converted to steam at it passes
through the steam
generator. The quality of the steam is measured as the percentage of vapor by
mass of
cold water. Thus, an 80 % quality steam is a steam flow containing 80 % of its
mass in
vapor.
[0014] Due to the presence of contaminants, such as hardness, salts, and
silica, the
maximum steam quality generated in OTSG and HRSG generators is typically
between
60 to 80 %. This means that 20 to 40 (Yo of the water mass entering the steam
generator remains as water at the exit of the steam generator. Feed water used
for
generating steam in OTSGs and HRSGs can come from many sources and, depending
upon the properties of the raw water, is treated to remove contaminants and
render it
suitable as a feed stream for a OTSG or HRSG.
[0015] In these styles of generators the maximum steam quality can be
limited by the
need to ensure that a continuous film of water coats the inner wall of boiler
tube
surfaces. If the continuous water film is not present, local dry spots will be
created,
leading to elevated tube temperatures and potential tube overheating. Also, by
converting 100 % of the water to steam in these areas, contaminants present in
the
water entering the steam generator can be deposited on the boiler tubes in the
form of
scale. These deposits impede heat transfer and further contribute to tube
overheating.
Significant tube overheating can result in the failure of the boiler tube.
Limiting the
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steam quality may ensure that sufficient water remains in the generator to
ensure that
the contaminants exceed their solubility limit, limiting the potential for
scaling.
[0016] In conventional thermal extraction processes, such as steam
floods, CSS
projects, SAGD infill wells, and sub-surface and surface mining using surface
extraction,
the recovery processes are able to effectively utilize a significant fraction
of the heat
contained within the condensate phase that is either injected into the
reservoir or
blended with the mined ore. For this reason, wet steam is sufficient for the
recovery
process.
[0017] Where the in situ recovery process being utilized can effectively
utilize the
heat contained in the condensate, the wet steam generated in the OTSG or HRSG
is
transported using pipelines to the wells and injected via wellbores into the
hydrocarbon
bearing reservoir. The injected steam heats the hydrocarbon, reducing its
viscosity and
allowing it to be recovered via either the same wells the steam was injected
into or via
one or more laterally and/or vertically offset production wells. In a surface
mining and
associated thermal based surface extraction technique the wet steam is used to
heat
the mined ore to allow its efficient extraction from the reservoir fabric.
[0018] The fluids produced as a result of the thermal recovery process
contain liquid
hydrocarbons recovered from the reservoir, water from condensed steam,
formation
water, and various minerals and other constituents which may be dissolved or
suspended in the mixture, along with steam and gaseous constituents. The
produced
fluids are typically transported to a centralized facility and separated,
forming vapor,
liquid hydrocarbon, and aqueous streams. An aqueous stream, which has as its
major
component produced water used for in situ recovery processes, can be treated
to
render it suitable for re-use as boiler feed water in the OTSG or HRSG. This
treatment
can include the removal of the majority of the hardness and a reduction in
both iron and
silica levels.
[0019] Where the recovery process being utilized cannot effectively
utilize the heat
contained in the condensate, the wet steam generated in the OTSG or HRSG is
separated into vapor and condensate streams downstream of the generator exit.
The
resulting dry steam is then transported to the wells via pipeline, while the
condensate
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stream contains essentially all of the impurities that were present in the
boiler feed
water, in addition to a significant quantity of heat.
[0020] As previously noted, the condensate stream can represent between 20 and
40% of the boiler feed water stream, depending on the quality of the steam
generated.
Managing the condensate can be problematic. If sufficient make-up water
capacity and
disposal capacity is required, the facility can be designed to maximize the
heat recovery
from the condensate before disposing of it. If make-up water capacity or
disposal
capacity is limited, then emphasis is placed on recycling the condensate.
[0021] One common practice is to recycle a portion of the condensate,
with or
without processing in a water treatment plant, and reusing it as boiler feed
water.
Typically the quantity of condensate that can be recycled is limited by the
build-up of
dissolved solids in the boiler feed water, which can precipitate in the boiler
tubes if a
portion of the condensate is not continuously purged from the system.
[0022] If the development is currently using two recovery processes, one
using dry
steam and the second using wet steam, a second practice may take the
condensate
and to blend it with the wet steam being utilized in the second recovery
process. This
can be an acceptable practice as long as the dry steam demand is small
compared to
the wet steam needs.
[0023] Various techniques have been developed to improve the quality of
a
condensate that is to be used as boiler feed water. For example, U.S. Patent
No.
7,591,309 to Minnich, et al., discloses an evaporation process for conversion
of
condensate into a high quality water stream and either a brine or a solids
reject stream
suitable for disposal. In the method, de-oiled produced water is processed
through an
evaporator at high pH and high pressure. The evaporator is driven by a
commercial
boiler. The steam from the evaporator can be used in SAGD. The evaporator
blowdown may be further treated in a crystallizing evaporator to provide a
zero liquid
discharge (ZLD) system. With most produced waters, at least 98 % of the
incoming
produced water stream can be recovered in the form of high pressure steam.
[0024] U.S. Patent Application Publication No. 2009/0133643 by Suggett,
et al.,
discloses a method and apparatus for generating steam while reducing the
quantity of
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boiler blowdown and, thus, increasing the amount of feed water that is re-used
or re-
cycled in generating the steam. The application claims that, on a sustained
basis, the
blowdown stream at the outlet of a once-through steam generator can be routed
to the
inlet of a second once-through steam generator that is in series with the
first, that
blowdown stream can be used to generate additional steam in the second once-
through
steam generator and further reduce the amount of blowdown, and that this can
be
accomplished without need of any treatment that reduces hardness or silica
levels of
the blowdown stream prior to its entering or during its entry into the inlet
of the second
once-through steam generator. The output of this second steam generator is a
substantially dry saturated steam vapor stream and, a blowdown stream whose
mass
rate has been reduced substantially from that of the blowdown stream exiting
the first
steam generator.
[0025] Similarly, Canadian Patent No. 2,621,991 to Speirs, et al.,
teaches a separate
OTSG (or HRSG), referred to as a boiler blowdown OTSG, which is located in
series
with one or more other OTSGs (or HRSGs) and can utilize the condensate from
the
initial OTSGs (or HRSGs) to generate wet steam. Reuse of the condensate in
this way
results in a significant reduction in the size of the condensate stream and an
increase in
the effective steam quality being generated. In the process boiler feed water
(BFW) of
sufficient quality is fed through one or more primary wet steam generators to
generate
primary wet steam. The primary wet steam is separated into primary dry steam
and a
primary liquid phase. The primary liquid phase can be fed into one or more
secondary
steam generators to generate secondary steam. The secondary steam generators
may
or may not be wet steam generators.
[0026] During the transition from a recovery process that is able to
effectively utilize
wet steam to a recovery process requiring dry steam the amount of condensate
that is
reused may need to be changed. The current approaches to increase the reuse of
condensate generally have a number of problems. For example, many developments
have a much larger requirement for wet steam than dry steam. Changing the
reuse of
the condensate may lose the benefits of the heat contained in the condensate.
New
water treatment technology may be needed in the operation. A series of boiler
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blowdown steam generators may be needed in order to match the volume of
condensate not being utilized in the dry steam scheme. Further, a large
fraction of the
installed steam generation capacity may need to be converted to dry steam
production
in order to allow one of the existing steam generators to be used as a
dedicated in
series boiler blowdown steam generator. As the techniques used to recover
resource
from a reservoir are adapted to the remaining resource present, the amounts
and
quality of the steam used may change. However, none of the references
described
above disclose tailoring the steam sources or quality to the changing needs of
the
reservoir over time.
SUMMARY
[0027] An embodiment of the present techniques provides a method for
generating
steam that is tailored to the changing needs of the field over time.
[0028] An exemplary embodiment provides a steam system. The steam system
includes a steam generator that includes boiler tubes that are modified to
form a
number of intermediate take-offs for removing water and steam from the boiler
tubes. A
number of intermediate separators are used to separate the water and steam at
each of
the number of intermediate take-offs A number of intermediate couplings are
used to
inject the water back into the boiler tubes downstream of each of the
plurality of
.. intermediate take-offs.
[0029] Another exemplary embodiment provides a method for improving recovery
from a hydrocarbon reservoir. The method includes matching a steam quality to
a
hydrocarbon development, wherein the steam is generated by a steam generator.
The
steam generator includes boiler tubes that are modified to form a number of
intermediate take-offs for removing water and steam from the boiler tubes. A
number of
intermediate separators separate the water and steam at each of the
intermediate take-
offs. A number of intermediate couplings inject the water back into the boiler
tubes
downstream of each of the plurality of intermediate take-offs. The steam
generator is
adapted to match a change in steam usage caused by a change in the hydrocarbon
development.
8
[0029a] Certain exemplary embodiments can provide a steam system, comprising:
a
steam generator comprising boiler tubes that are modified to form a plurality
of
intermediate take-offs for removing water and steam from the boiler tubes; a
plurality of
intermediate separators to separate the water and steam at each of the
plurality of
intermediate take-offs; and a plurality of intermediate couplings to inject
the water back
into the boiler tubes downstream of each of the plurality of intermediate take-
offs;
wherein the plurality of intermediate separators comprises a plurality of
condensate
reservoirs in a single vessel, wherein each of the plurality of condensate
reservoirs is
.. separated from other condensate reservoirs by a weir.
[0029b] Certain exemplary embodiments can provide a method for
improving
recovery from a hydrocarbon reservoir, the method comprising: matching a steam
quality to a hydrocarbon development, wherein the steam is generated by a
steam
generator comprising: boiler tubes that are modified to form a plurality of
intermediate
take-offs for removing water and steam from the boiler tubes; a plurality of
intermediate
separators to separate the water and steam at each of the plurality of
intermediate take-
offs; and a plurality of intermediate couplings to inject the water back into
the boiler
tubes downstream of each of the plurality of intermediate take-offs; and
adapting the
steam generator to match a change in steam usage caused by a change in the
hydrocarbon development; wherein the plurality of intermediate separators
comprises a
plurality of condensate reservoirs in a single vessel, wherein each of the
plurality of
condensate reservoirs is separated from other condensate reservoirs by a weir.
8a
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DESCRIPTION OF THE DRAWINGS
[0030] The advantages of the present techniques are better understood by
referring
to the following detailed description and the attached drawings, in which:
[0031] Fig. 1 is a drawing of a development 100 illustrated the use of both
a surface
mining recovery process and a steam assisted gravity drainage (SAGD) recovery
process to harvest hydrocarbons from a reservoir;
[0032] Fig. 2 is a drawing of a conventional steam generation system
that may be
utilized to generate steam for thermal or thermal-solvent recovery processes,
such as
CSS;
[0033] Fig. 3 is a drawing of a steam generation system that uses three
steam
generators in parallel to generate wet steam for a thermal recovery process;
[0034] Fig. 4 shows a steam generation system that can be utilized to
generate dry
steam for thermal recovery processes such as SAGD developments;
[0035] Fig. 5 is a drawing of a steam generation system in a series design
in which
the condensate from a first steam generator is separated from the dry steam in
a
separator and used as a feed water stream for a smaller steam generator;
[0036] Fig. 6 is a drawing of a steam generation system using multiple
steam
generators for the purpose of generating primarily dry steam;
[0037] Fig. 7 is a drawing of a steam generation system after conversion of
one
steam generator to the production of dry steam;
[0038] Fig. 8 is a drawing of a steam generation system after conversion
of two
steam generators to the production of dry steam;
[0039] Fig. 9 is a drawing of a steam generation system that may provide
similar
.. production of wet and dry steam as described for Figs. 7 and 8;
[0040] Fig. 10 is a drawing of a steam generation system that may not
provide
material steam quality improvement, but may provide significant operating
flexibility;
[0041] Fig. 11 is a drawing of the system of Figs. 7 and 8 after the
third steam
system is converted to dry steam service;
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[0042] Fig. 12 is a drawing of a steam generation system in which three
steam
systems operate in parallel and generate dry steam by cascading the condensate
sequentially to the inlet of the adjacent steam system;
[0043] Fig. 13 is a drawing of a steam generation system showing that
the cascading
process may be applied to steam systems having multiple steam generators
operating
in parallel;
[0044] Fig. 14 is a drawing of a steam generation system that includes a
seventh
steam generator installed in a fourth steam system;
[0045] Fig. 15 is a drawing of a steam generator that is modified to
increases both
throughput and dry steam production; and
[0046] Fig. 16 is a process flow diagram of a method for tailoring the
quality of steam
production to field needs;
[0047] Fig. 17 is a drawing of a development for which dry steam is
separated from
the wet steam and the different steam lines are directed to regions of the
field where
recovery processes efficiently use the wet or dry steam;
[0048] Fig. 18 is a diagram of a SAGD process with infill wells where
the efficiency of
the process is enhanced by directing dry steam to the SAGD injection wells
1804 and
wet steam to the infill well injectors; and
[0049] Fig. 19 is another diagram of a SAGD process with infill wells
where the
.. efficiency of the process is enhanced by directing dry steam to the SAGD
injection wells
1906 and wet steam to the infill well injectors.
DETAILED DESCRIPTION
[0050] In the following detailed description section, specific
embodiments of the
present techniques are described. However, to the extent that the following
description
is specific to a particular embodiment or a particular use of the present
techniques, this
is intended to be for exemplary purposes only and simply provides a
description of the
exemplary embodiments. Accordingly, the techniques are not limited to the
specific
embodiments described below, but rather, include all alternatives,
modifications, and
equivalents falling within the true spirit and scope of the appended claims.
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[0051] At the outset, for ease of reference, certain terms used in this
application and
their meanings as used in this context are set forth. To the extent a term
used herein is
not defined below, it should be given the broadest definition persons in the
pertinent art
have given that term as reflected in at least one printed publication or
issued patent.
Further, the present techniques are not limited by the usage of the terms
shown below,
as all equivalents, synonyms, new developments, and terms or techniques that
serve
the same or a similar purpose are considered to be within the scope of the
present
claims.
[0052] As used herein, "bitumen" is a naturally occurring heavy oil
material. It is
often the hydrocarbon component found in oil sands. Bitumen can vary in
composition
depending upon the degree of loss of more volatile components. It can vary
from a very
viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types
found in
bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical
bitumen
might be composed of:
19 wt. % aliphatics, which can range from 5 wt. %-30 wt. %, or higher;
19 wt. % asphaltenes, which can range from 5 wt. %-30 wt. %, or higher;
30 wt. % aromatics, which can range from 15 wt. %-50 wt. %, or higher;
32 wt. % resins, which can range from 15 wt. %-50 wt. %, or higher; and
some amount of sulfur, which can range in excess of 7 wt. %.
In addition bitumen can contain some water and nitrogen compounds ranging from
less
than 0.4 wt. % to in excess of 0.7 wt. %. The metals content, while small, can
be
removed to avoid contamination of the product synthetic crude oil (SCO).
Nickel can
vary from less than 75 ppm (part per million) to more than 200 ppm. Vanadium
can
range from less than 200 ppm to more than 500 ppm. The percentage of the
hydrocarbon types found in bitumen can vary.
[0053] As used herein, "condensate" includes liquid water formed by the
condensation of steam. Steam may also entrain liquid water, in the form of
water
droplets. This entrained water may also be termed condensate, as it may arise
from
condensation of the steam, although the entrained water droplets may also
originate
from the incomplete conversion of liquid water to steam in a boiler.
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[0054] As used herein, a "development" is a project for the recovery of
hydrocarbons
using integrated surface facilities and long term planning. The development
can be
directed to a single hydrocarbon reservoir, although multiple proximate
reservoirs may
be included.
[0055] As used herein, "exemplary" means "serving as an example, instance,
or
illustration." Any embodiment described herein as "exemplary" is not to be
construed as
preferred or advantageous over other embodiments.
[0056] As used herein, "facility" as used in this description is a
collection of physical
equipment through which hydrocarbons and other fluids may be either produced
from a
reservoir or injected into a reservoir. A facility may also include equipment
which can
be used to control production or completion operations. In its broadest sense,
the term
facility is applied to any equipment that may be present along the flow path
between a
reservoir and its delivery outlets. Facilities may comprise production wells,
injection
wells, well tubulars, wellhead equipment, gathering lines, manifolds, pumps,
compressors, separators, surface flow lines, steam generation plants,
extraction plants,
processing plants, water treatment plants, and delivery outlets. In some
instances, the
term "surface facility" is used to distinguish those facilities other than
wells.
[0057] As used herein, a "heat recovery steam generator" or HRSG is a
heat
exchanger or boiler that recovers heat from a hot gas stream. It produces
steam that
can be used in a process or used to drive a steam turbine. A common
application for an
HRSG is in a combined-cycle power plant, where hot exhaust from a gas turbine
is fed
to the HRSG to generate steam which in turn drives a steam turbine. As
described
herein, the HRSG may be used to provide steam to an enhanced oil recovery
process,
such as CSS or SAGD.
[0058] As used herein, "heavy oil" includes oils which are classified by
the American
Petroleum Institute (API), as heavy oils or extra heavy oils. In general, a
heavy oil has
an API gravity between 22.3 (density of 920 kg/m3 or 0.920 g/cm3) and 10.0
(density
of 1,000 kg/m3 or 1 g/cm3). An extra heavy oil, in general, has an API gravity
of less
than 10.00 (density greater than 1,000 kg/m3 or greater than 1 g/cm3). For
example, a
source of heavy oil includes oil sand or bituminous sand, which is a
combination of clay,
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sand, water, and bitumen. The thermal recovery of heavy oils is based on the
viscosity
decrease of fluids with increasing temperature or solvent concentration. Once
the
viscosity is reduced, the mobilization of fluids by steam, hot water flooding,
or gravity is
possible. The reduced viscosity makes the drainage quicker and therefore
directly
contributes to the recovery rate.
[0059] As used herein, a "hydrocarbon" is an organic compound that
primarily
includes the elements hydrogen and carbon, although nitrogen, sulfur, oxygen,
metals,
or any number of other elements may be present in small amounts. As used
herein,
hydrocarbons are used to refer to components found in bitumen, or other oil
sands.
[0060] As used herein, a "reservoir" is a subsurface rock or sand formation
from
which a production fluid can be harvested. The rock formation may include
sand,
granite, silica, carbonates, clays, and organic matter, such as oil, gas, or
coal, among
others. Reservoirs can vary in thickness from less than one foot (0.3048 m) to
hundreds of feet (hundreds of m).
[0061] As used herein, and discussed in detail above, "Steam Assisted
Gravity
Drainage" (SAGD), is a thermal recovery process in which steam is injected
into a first
well to lower a viscosity of a heavy oil, and fluids are recovered from a
second well.
Both wells are usually horizontal in the formation and the first well lies
above the second
well. Accordingly, the reduced viscosity heavy oil flows down to the second
well under
.. the force of gravity, although pressure differential may provide some
driving force in
various applications.
[0062] As used herein, a "steam generator" may include any number of
devices used
to generate steam for a process facility, either directly or as part of
another process.
Steam generators may include, for example, heat recovery steam generators
(HRSG),
and once through steam generators (OTSG), among others. The steam may be
generated at a number of quality levels. Steam quality is measured by the mass
fraction of a cold water stream that is converted into a vapor. For example,
an 80 %
quality steam has around 80 wt. % of the feed water converted to vapor. The
steam is
generated as wet steam that contains both steam vapor and associated
condensate (or
water). The wet steam may be passed through a separator to generate a dry
steam,
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i.e., without entrained condensate. As a result of the separation, the
separator also
generates a liquid condensate stream.
[0063] As used herein, a "steam system" includes one or more steam generators
running in parallel from a common feed water source and feeding steam to a
common
outlet. The steam system may include any number or types of steam generators
in
parallel. Often, the parallel steam generators of the steam system generate
steam at a
similar quality level.
[0064] As used herein, "substantial" when used in reference to a
quantity or amount
of a material, or a specific characteristic thereof, refers to an amount that
is sufficient to
provide an effect that the material or characteristic was intended to provide.
The exact
degree of deviation allowable may in some cases depend on the specific
context.
[0065] As used herein, "thermal recovery processes" include any type of
hydrocarbon recovery process that uses a heat source to enhance the recovery,
for
example, by lowering the viscosity of a hydrocarbon. These processes may be
based
on heated water, wet steam, or dry steam, alone, or in any combinations.
Further, any
of these components may be combined with solvents to enhance the recovery.
Such
processes may include subsurface processes, such as cyclic steam stimulation
(CSS),
steam flooding, and SAGD, among others, and processes that use surface
processing
for the recovery, such as sub-surface mining and surface mining.
[0066] As used herein, a "wellbore" is a hole in the subsurface made by
drilling or
inserting a conduit into the subsurface. A wellbore may have a substantially
circular
cross section or any other cross-sectional shape, such as an oval, a square, a
rectangle, a triangle, or other regular or irregular shapes. As used herein,
the term
"well," when referring to an opening in the formation, may be used
interchangeably with
the term "wellbore." Further, multiple pipes may be inserted into a single
wellbore, for
example, to limit frictional forces in any one pipe.
[0067] Overview
[0068] The thermal recovery processes chosen for a particular stage of a
development sets the steam quality to be utilized. For example, in the early
cycles of a
recovery process such as cyclic steam stimulation (CSS) wet steam is
sufficient, since
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the majority of recovery mechanisms are not related to gravity drainage, but
may
include dilation/compaction, solution gas drive, water flashing, and the like.
As the CSS
recovery process matures, the significance of these additional recovery
mechanisms
declines and the recovery role of gravity drainage increases. Similarly,
conventional
.. steam flood processes for hydrocarbon recovery may use a combination of
heating and
the imposition of a significant pressure gradient to displace the oil to the
offset
production wells, allowing the use of wet steam. However, once a significant
aqueous
or vapor saturation connects the injection wells to the production wells, it
may no longer
be possible to impose a pressure gradient, and gravity drainage will become
dominant
recovery mechanism. As gravity drainage becomes more important, it becomes
more
efficient to use higher quality steam or even dry steam.
[0069] In addition to different stages of the recovery, different
recovery processes
may be used in a single development. For example, in shallow hydrocarbon
deposits
certain areas of the deposit may be reached with surface mining and extraction
techniques, while other areas can be harvested with in situ recovery
techniques.
Different types of techniques may utilize different balances of steam or water
quality.
[0070] Embodiments described herein provide steam generation designs and
methods for transitioning from a recovery process that utilizes wet steam to a
recovery
process that utilizes dry steam, or vice-versa. The systems and methods may
reduce
facility costs and make-up water requirements when generating steam in
developments
that use thermal recovery processes requiring dry steam. In some embodiments,
the
condensate stream may be cascaded between steam generators. In these
embodiments, the residual condensate can be blended with the boiler feed water
being
fed to an adjacent steam system in such a way that the dissolved contaminants
do not
compromise steam generator function. As used here, "cascading" indicates that
the
items are connected successively end to start to form a single path.
[0071] Fig. 1 is a drawing of a development 100 illustrating the use of
both a surface
mining 102 recovery process and a steam assisted gravity drainage (SAGD) 104
recovery process to harvest hydrocarbons 106 from a reservoir 108. It will be
clear that
the techniques described herein are not limited to this combination, or these
specific
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techniques, as any number of techniques or combinations of techniques may be
used in
embodiments described herein. The surface mining 102 may be used to reach a
portion of the reservoir 108 that is closer to the surface, while the SAGD 104
recovery
may be used to access hydrocarbons in a portion of the reservoir 108 that is
at a
greater depth. In the development 100, a steam generation facility 109 is used
to
generate steam 110, which can be provided to surface separation facility 112
and an
injection facility 114. The steam 110 may include both wet steam and dry
stream, for
example, carried in different pipes from the steam generation facility 109.
[0072] The surface mining 102 uses heavy equipment 116 to remove hydrocarbon
containing materials118, such as oil sands, from the reservoir 108. The
hydrocarbon
containing materials are offloaded at the separation facility 112, where a
thermal
process, such as a Clark hot water extraction (CHWE), among others, may be
used to
separate a hydrocarbon stream 120 from a tailings stream 122. The tailings
stream 122
may be sent to a tailings pond 124, or may be injected into a sub-surface
formation for
disposal. A water stream 126 may be recycled to the steam generation facility
109.
The extraction process may utilize wet steam from the steam generation
facility 108.
[0073] The SAGD 104 process injects the steam 110 through injection
wells 128 to
harvest hydrocarbons by raising the temperature of a portion 130 of the
reservoir 108 to
lower the viscosity of the hydrocarbons 131, allowing the hydrocarbons 131 to
flow to
collection wells 132. Although, for the sake of clarity, the injection wells
128 and
collection wells 132 are shown as originating from different locations in Fig.
1, these
wells 128 and 132 may be drilled from the same surface pads to enable easier
tracking
between the wells 128 and 132. The resulting streams 134 from the reservoir
108 may
include the hydrocarbons 131 and the condensate from the steam 110. The
streams
134 can be processed at a surface facility 136 to remove at least some of the
water.
The SAGD process 104 may utilize higher quality or dry steam from the steam
generation facility 109.
[0074] The hydrocarbon stream 138 and water stream 140 from the SAGD process
104 may be sent to a transportation facility 142, which may provide further
separation
.. and purification of the incoming streams 120, 138, and 140, prior to
sending the
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marketable hydrocarbons 106 on to further processing facilities. The resulting
process
water 144 can be returned to the steam generation facility 109 for recycling.
[0075] Fig. 2 is a drawing of a conventional steam generation system 200
that may
be utilized to generate steam for thermal or thermal-solvent recovery
processes, such
as CSS. In this figure, a feed water stream 202 is treated in a water
treatment facility
204 to reduce the concentration of contaminants that may cause scale to be
deposited
in the steam generator 206.
[0076] The water treatment facility 204 may use a number of techniques
to reduce
the contaminants in the feed water stream 202, including, for example, hot
lime
softening which may lower the concentration of contaminates by forcing their
precipitation. Any number of other techniques may also be used alone or in
various
combinations, including evaporative purification (distillation), membrane
purification,
chemical purification, ion exchange, and the like.
[0077] The treated water provides a boiler feed water 205 that can be
used by a
.. steam generator 206 to generate wet steam 208. The wet steam 208 can be
transported via pipeline to a development where is it injected into a
reservoir using
wells. The steam generator 206 may be any type of steam generator, for
example, a
once-through steam generator (OTSG), a heat-recovery steam generator (HRSG),
and
the like. Further, the steam generation system 200 is not limited to a single
steam
generator 206, but may include any number of steam generators 206 in parallel.
[0078] Fig. 3 is a drawing of a steam generation system 300 that uses
three steam
generators 206 in parallel to generate wet steam for a thermal recovery
process. Like
numbered items are as described in the figures above. As noted above, a steam
generation system 300 may include a number of parallel steam generators 206,
which
may be any combinations of OTSG or HRSG units. Each steam generator 206 is
supplied with boiler feed water 205 from the water treatment facility 204. The
resulting
wet steam flow 208 from each steam generator 206 can be combined to form a
single
wet steam stream 302 that may be transported to the injection wells or used in
surface
facilities. The steam generation systems 200 and 300, discussed with respect
to Figs. 2
.. and 3, may be adapted to provide dry steam as discussed with respect to
Fig. 4.
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[0079] Fig. 4 shows a steam generation system 400 that can be utilized
to generate
dry steam 402 for thermal recovery processes such as SAGD developments. Like
numbered items are as described in the figures above. Once the wet steam 208
exits
the steam generator 206 it is sent to a separator 404, which separates the two
phases.
.. The vapor phase or dry steam 402 leaves the separator 404 and may then be
transported via pipeline to the development where is it injected into a
reservoir using
wells, for example, as discussed with respect to Fig. 1.
[0080] The liquid phase or condensate 406 can be sent to disposal 408,
such as
injection into a waste well. A portion 410 of the condensate 406 can be
recycled to the
inlet 412 of the steam generator 206. Typically, less than 100 % of the
condensate 406
will be recycled, as any dissolved salts in the condensate 406 will be
concentrated over
time and can foul the boiler tubes in the steam generator 206. Therefore, when
recycling the condensate 406, at least a portion is continuously purged to
disposal 408
and replaced by clean boiler feed water 205.
[0081] Although not shown in Fig. 4, the condensate 406 that is purged from
the
system can go through additional processing to recover heat, for example,
through the
use of heat exchange devices. Further, high quality make-up water may be
obtained
from the condensate 406, for example, by processing the condensate 406 in the
water
treatment facility 204. For example, this may be performed by flashing the
stream to a
lower pressure and condensing the steam stream that results from that pressure
change, among other techniques.
[0082] Fig. 5 is a drawing of a steam generation system 500 in a series
design in
which the condensate 406 from a first steam generator 206 is separated from
the dry
steam 402 in a separator 404 and used as a feed water stream for a smaller
steam
generator 502. Like numbered items are as described in the figures above. The
wet
steam 504 generated by the smaller steam generator 502 can be passed through a
second separator 506. The dry steam 508 from the second separator 506 can be
combined with the dry steam 402 from the first separator 404 to form a
combined dry
steam 510, which may be transported to injection wells by a pipeline. The
condensate
512 from the second separator 506 may be sent to disposal 408, such as a
disposal
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well or pond. A portion of the condensate 512, or even all, may be returned to
the water
treatment facility 204 to separate impurities and recover the water.
[0083] The smaller steam generator 502 may be termed a "blowdown" steam
generator. If contaminants in the condensate 406 are sufficiently below their
saturation
levels, the use of the two steam generators 206 and 502 in series allows the
steam
quality to be increased, as measured per unit of boiler feed water 205
utilized.
[0084] Fig. 6 is a drawing of a blowdown steam generation system 600
using
similarly sized steam generators 206 and 602. Like numbered items are as
described in
the figures above. In the blowdown steam-generation system 600, the number of
parallel steam generators 206 used to supply a single blowdown steam generator
602 is
1 /(1-the generated steam quality). Thus, if the desired steam quality is 80
%, five
parallel steam generators 206 are used ahead of each blowdown steam generator
602,
as is represented in Fig. 6. This configuration will often generate a very
large quantity
of steam and, therefore, may be relevant for large projects.
[0085] Tailoring steam generation for project development
[0086] In an embodiment, steam production may be tailored to fit the
current needs
of the development. This may allow conversion of particular steam generation
systems
from producing only wet steam to producing a combination of wet and dry steam,
or
only dry steam. Further, as the development process continues, the proportion
of dry
steam generated may be increased.
[0087] Although embodiments are not limited to the following conditions,
for the
purposes of this explanation, it is assumed that an existing commercial
development
starts by using 100 % of the steam capacity to support a CSS development using
wet
steam. As the development matures, a steam flood based follow-up process is
implemented, resulting in 67 % of the steam capacity being used to support the
CSS
operation with wet steam, and 33 % being used for the steam flood as dry
steam. As
the CSS resource continues to be depleted, a SAGD development is implemented,
resulting in 33 % of the steam capacity being used for CSS (wet steam), 33 %
being
used for the steam flood (dry steam) and 33 % now being used in a new SAGD
development (dry steam). Later, the CSS operations are completed and 33 % of
the
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steam capacity supports a steam flood (dry steam) and 67 % is used to support
an
expanded SAGD development (dry steam).
[0088] The development with the CSS process may be supported by the steam
generation system 300 discussed with respect to Fig. 3, which may represent a
starting
point for the installed steam capacity of the development. At some point, the
CSS
production may no longer be economical, and a development decision is made to
convert a portion of the existing development to a steam flood. Although, a
new steam
generation system may be installed to create the dry steam this may be costly.
Accordingly, in an embodiment, one of the three steam generators is converted
to dry
service.
[0089] Fig. 7 is a drawing of a steam generation system 700 after
conversion of one
steam generator 206 to the production of dry steam. Like numbered items are as
described in the figures above. The wet steam 208 produced from the converted
steam
generator 206 is sent to a separator 404 where the dry steam 402 is separated
and then
sent to the field via a dry steam pipeline. This may be termed the first steam
system
702. The separated condensate 406 from the first steam system 702 can then be
cascaded to the inlet 704 of a second steam system 706 that has another steam
generator 206. The net effect of the cascading arrangement is a comparable
reduction
in the boiler feed water 205 provided to the second steam system 706 from the
water
treatment facility 204. Thus, water consumption, operating costs, and energy
consumption are reduced.
[0090] The wet steam 208 generated in the second steam system 706 has an
increased level of contaminants, which may necessitate a reduction in the
steam quality
generated in the second steam system 706. For example, if the concentration of
the
contaminants in the wet steam 208 from the second steam system 706 exceeds a
precipitation limit, the contaminants may precipitate in the tubes of the
steam generator
206, causing damage. However, as the wet steam 208 from the second steam
system
706 may be used for a recovery process where wet steam 208 is acceptable, a
reduction in quality may not materially impact recovery performance. The wet
steam
208 from the two remaining steam systems 706 and 708 is combined to form a
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wet steam stream 302, which is sent to the remaining CSS wells. At some point,
as
mentioned above, a further reduction in CSS may be desired, and more capacity
may
be converted to the production of dry steam 402.
[0091] If an increase in wet steam may be useful, a bypass line 710 can
be included
to allow wet steam 208 from the first steam system 702 to bypass the separator
404
and add to the amount available for the wet steam stream 302. For example,
this may
be useful if a new portion of the development is opened, increasing the wet
steam
demand after the conversion. As described below, further increases in dry
steam may
be achieved by adding directing wet steam 208 from the second steam system 706
to
the inlet 704 of the third steam system 712, as described with respect to Fig.
8.
[0092] Fig. 8 is a drawing of a steam generation system 800 after
conversion of two
steam generators 206 to the production of dry steam. Like numbered items are
as
described above. Wet steam 208 from the second steam system 706 is sent to a
separator 404 where the dry steam 402 is separated, mixed with the dry steam
402
from the first steam system 702, and then sent to the field via a dry steam
pipeline. The
separated condensate 406 from the second steam system 706 is cascaded to the
inlet
712 of the third steam system 708. Again, the net effect of this cascading
action is a
comparable reduction in the boiler feed water provided to the third steam
system 708
from the water treatment facility 204 and, hence, a further reduction in water
consumption, operating costs, and energy use.
[0093] The wet steam 208 generated in the third steam system 708 has a further
increased level of contaminants, which may also necessitate a reduction in the
steam
quality generated in this third steam system 708. As the wet steam 208 may be
used
for a recovery process, e.g., CSS, where wet steam is acceptable, a reduction
in quality
may not materially impact recovery performance. The wet steam 208 from the
remaining steam system 708 is sent to the remaining CSS wells as wet steam
stream
302.
[0094] As discussed with respect to Fig. 7, the configuration shown in
Fig. 8 may
include bypass lines 710 to allow the wet steam 208 from the first steam
system 704
and the second steam system 706 to bypass the separators 404. This may allow
for an
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easy conversion back to wet steam 208 production from each system, if the
amount
used for the wet steam stream 302 to the wells increases.
[0095] Fig. 9 is a drawing of a steam generation system that may provide
similar
production of wet and dry steam as described for Figs. 7 and 8. Like numbered
items
.. are as described above. In this case the steam generators 206 each feed a
wet steam
208 into a common wet steam header 902. A first portion 904 of the wet steam
208
may be sent to a field as the wet steam stream 302. The remaining portion 906
of the
wet steam 208 from the wet steam header 902 is sent to a separator 404, from
which
the dry steam 402 may be sent to a field. The condensate 406 can be recycled
to the
feed water header 908, displacing a comparable quantity of boiler feed water
205 from
the water treatment facility 204.
[0096] In this design, a reasonably continuous demand for wet steam 208
from all
three steam generators 206 may help to ensure that the contaminant levels in
the boiler
feed water header 908 remain at acceptable levels. Further, the dilution of
the
condensate 406 in the boiler feed water header 908 may be uniform across the
inlets of
all three generators 206, uniformly lowering the concentration of
contaminants. This
design may be more flexible in its ability to respond to short term swings in
the demand
for wet steam 208 and dry steam 402 than, for example, the configuration shown
in Fig.
8.
[0097] Fig. 10 is a drawing of a steam generation system 1000 that may not
provide
material steam-quality improvement, but may provide significant operating
flexibility.
Like numbered items are as described above. As described for Fig. 9, the steam
generators 206 all feed into a common wet steam header 902, with a portion 906
of the
wet steam 208 being sent to a separator 404. From the separator 404, the dry
steam
402 can be sent to the injection wells via a dry steam pipeline. The separated
condensate 406 can then be combined with the remaining wet steam 208 and sent
to
the field as wet steam stream 302.
[0098] This design may be beneficial when the expected demand for dry steam
402
is small relative to the demand for wet steam 208, as the impact of the
quality of the wet
steam 208 will be small. It may also be used when the recovery process
utilizing the
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wet steam 208 is not impacted by significant reductions in quality. For
example,
supplying the heat used for a thermal recovery process used in a surface
mining
project, such as a Clark hot water process used to extract hydrocarbons from
oil sands.
[0099] Fig. 11 is a drawing of the systems of Figs. 7and 8 after the
third steam
system 708 is converted to dry steam service. Like numbered items are as
described
above. In the third steam system 708, wet steam 208 is sent to a separator 404
where
the dry steam 402 is separated and then combined with dry steam 402 from the
first
steam system 702 and the second steam system 706, and sent to the field via a
dry
steam pipeline. Again, the net effect of the cascading condensate 402 from the
first
steam system 702 and the second steam system 706 is an increase in the
concentration of contaminants in the condensate. As less and less wet steam
208 is
used in the development, these contaminants will need to be reduced by other
techniques. For example, the condensate 406 from the third steam system 708
may be
sent to disposal 408. With no additional wet steam requirements, the existing
wet
steam pipeline can be converted to dry steam service.
[0100] As for the configurations discussed with respect to Figs. 7 and
8, the
conversion process piping has bypass lines 710 to allow the steam generation
system
1100 to revert to an increase in production of wet steam 208. Thus, as
fluctuations in a
balance between wet steam 208 and dry steam 402 change with time, the steam
generation system 1100 has the flexibility to adapt to these changing needs.
For
example, this flexibility allows the steam generation system 1100 to provide a
different
balance of steam if production is started in a new area of the development.
[0101] The process of cascading the condensate 406 between the parallel
steam
systems 702, 706, and 708 will result in lower steam systems 706 and 708
operating at
a lower pressure than the steam system 702 and 706 from which the condensate
406
was sourced. This will result in the wet steam 208, for example, to be used in
the CSS
recovery process, being provided at the lowest pressure of the steam systems
702, 706,
and 708. While this outcome may be satisfactory if a CSS process is utilizing
sub-
fracture pressures for steam injection, it may be problematic if higher
pressures are
useful.
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[0102] In situations where it is useful to operate all of the steam
systems 702, 706,
and 708 at the same discharge pressure or to operate the wet steam 208 at a
higher
discharge pressure, the pressure of the condensate 406 being cascaded can be
boosted using a pump. If this is to be done while the condensate 406 is hot,
the design
can account for the frictional pressure drop by increasing the head gain from
the base of
the separator 404. This may be useful for preventing steam vapor from forming
at the
pump suction, which could lead to cavitation.
[0103] If the pumping is to be done after the condensate 406 is cooled,
then a
beneficial use may be made of the heat contained in the condensate 406. For
example,
one option would be to exchange the heat of the condensate 406 with the boiler
feed
water stream as it is entering a hot lime softener (HLS) in the water
treatment facility
204. This may reduce the steam consumed in the HLS operation.
[0104] Fig. 12 is a drawing of a steam generation system 1200 in which
three steam
systems 702, 706, and 708 operate in parallel and generate dry steam 402 by
cascading the condensate 406 sequentially to the inlet 704 and 712 of the
adjacent
steam system 706 and 708. Like numbered items are as described above. For
purposes of clarity, this drawing has been simplified from the steam
generation system
of Fig. 11 by the elimination of the bypass lines 710 used to reverse the
conversion,
e.g., to allow the production of wet steam 208.
[0105] The current techniques allow dry stream 402 to be generated using
water with
the least quantity of contaminants. Blending the cascaded condensate 406 with
the
feed water helps to moderate the concentration of the contaminants in an
adjacent
steam system 706 and 710. In this way the steam systems used for dry steam 402
have the potential to generate higher quality steam than the remaining steam
generators being used for wet steam service.
[0106] Fig. 13 is a drawing of a steam generation system 1300 showing
that the
cascading process may be applied to steam systems 1302, 1306, and 1308 having
multiple steam generators 206 operating in parallel. Like numbered items are
as
described above. Thus, the first steam system 1302 has two steam generators
206 in
parallel in this example. The wet steam 208 is passed to a separator 404, with
the
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condensate 406 from the separator 404 fed to the inlet 1304 of the two steam
generators 206 in the second steam system 1306. Similarly, the condensate 406
from
the second steam system 1306 is fed to the inlet 1310 of the two steam
generators 206
in the third steam system 1308.
[0107] The steam generation system 1300 may also be used to present a
simplified
material balance showing the beneficial effects of cascading the condensate
406
between the steam generators 206 as the steam generators 206 are converted
from wet
steam service to dry steam service. For purposes of this example, it may be
assumed
that each of the steam generators 206 is processing 100 units of water and is
generating steam with an 80 % quality, i.e., providing 80 units of steam.
Thus, the
treatment facility 204 may have been designed to process 600 units of feed
water
stream 202 from point 1 (as indicated by the numbered diamond). At point 2,
200 units
of the feed water from the treatment facility 204 are consumed by the first
steam system
1302, i.e., 100 units in each steam generator 206. The separator 404 separates
the wet
steam 208 from the steam generators 206 into 160 units of dry steam at point 3
and 40
units of condensate 406 at point 4. The condensate 406 is sent to the inlet
1304 of the
second steam system 1306. Thus, at point 5, 160 units of boiler feed water 205
from
the water treatment facility 204 is used to give a total water feed to the
second steam
system 1306 of 200 units.
[0108] The wet steam 208 from the steam generators 206 of the second steam
system 1306 is fed to a separator 404, which separates the wet steam 208 into
160
units of dry steam at point 6 and 40 units of condensate at point 7. The
condensate 406
from the second steam system 1306 is fed to the inlet 1310 of the third steam
system
1308. Thus, at point 8, 160 units of boiler feed water 205 from the water
treatment
facility 204 is used to provide a total water feed of 200 units to the third
steam system
1308.
[0109] The wet steam 208 from the steam generators 206 of the third steam
system
1308 is fed to a separator 404, providing 160 units of dry steam at point 9.
The dry
steam 402 from the first steam system 1302, the second steam system 1306, and
the
third steam system 1308 is combined to give a total of 480 units of dry steam
402 at
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point 10, which may be sent to the injection wells in a development. The 40
units of
condensate 406 from the separator 404 of the third steam system 1308 will have
the
highest concentration of contaminants, and can be sent to disposal at point
11. Thus,
by converting all three steam systems 1302, 1306, and 1308 to dry steam
service, 80
units of feed water that could be provided from the water treatment facility
204 are freed
for other purposes, such as increasing the amount of steam that may be
generated.
[0110] Fig. 14 is a drawing of a steam generation system 1400 that
includes a
seventh steam generator 206 installed in a fourth steam system 1402. Like
numbers
are as described before, and the mass balance at similarly numbered points is
the same
as discussed with respect to the steam generation system 1300 of Fig. 13.
[0111] In contrast to disposing of all of the condensate 406 from the
third steam
system 1308, as shown in Fig. 13, the condensate 406 may be divided into two
equal
portions. A first portion of 20 units, indicated at point 12, may be fed to
the inlet 1404 of
the fourth steam system 1402. Thus, the remaining 80 units of capacity from
the feed
water treatment facility 204 are used to provide 100 units to the fourth steam
system
1402 at point 13. The wet steam 208 from the steam generator 206 in the fourth
steam
system 1402 is passed to a separator 404, resulting in 80 units of dry steam
402 at
point 14. The dry steam 402 at point 14 can be combined with the 480 units of
dry
steam at point 10, to provide 560 units of dry steam 402 to the injection
wells at point
15.
[0112] The remaining portion of 20 units of condensate from the
separator 404 of the
third steam system 1308, at point 16, may be combined with the 20 units of
condensate
from the separator 404 of the fourth steam system 1402 at point 17, resulting
in 40 units
of condensate 406 which may be sent to disposal at point 11. As a result all
of the
available water treatment capacity is being utilized. Although the fourth
steam system
1402 generator is shown in dry steam service, it could be used in either wet
steam or
dry steam service.
[0113] In an embodiment, the surplus capacity for boiler feed water 205
may be
utilized by increasing the throughput of the existing steam generators 206.
This may be
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done when the objective is to produce dry steam without compromising the
design
constraints, e.g., by installing more steam generators 206.
[0114] Modification of a steam generator to increase inherent capacity
[0115] In an embodiment, a steam generator 206 may be modified to
increase
.. capacity by functioning like a series of smaller steam generators. This may
also have
the additional benefit of increasing the throughput through the steam
generator 206.
[0116] Fig. 15 is a drawing of a steam generator 1500 that is modified
to increase
both throughput and dry steam production. The steam generator 1500 may contain
multiple tube bundles arranged into sections, including section A 1502,
section B 1504,
section C 1506, and section C' 1508. The outlet of each tube bundle provides
the inlet
feed for the next tube bundle, with the exception of sections C 1506 and C'
1508, which
may be placed in parallel to provide a spare section while one tube bundle is
out of
service for cleaning or tube replacement. Embodiments are not limited to steam
generators that have segmented tubing bundles. In some embodiments, the tubing
may
.. be contiguous prior to modification, and each tube may be modified to
direct the steam
and water to a separator. Further, the modification may be done on groups of
tubes as
a unit.
[0117] In the steam generator 1500, the feed water 1510 is fed into the
tube bundle
of section A 1502. The feed water 1510 may be boiler feed water 205 from the
water
treatment facility 204, or may be a blend of boiler feed water 205 and
condensate 404.
An intermediate take-off 1512, for example, located after tubes in section A
1502,
diverts the steam and water from section A 1502 to a separator 1514, which
separates
the dry steam 1516 from the condensate 1518. The separator 1514 may be a
conventional gravity driven separator or may be a centrifugal separator used
to form
liquid and vapor streams by centripetal force.
[0118] The condensate 1518 is then returned to the steam generator 1500
as the
feed to section B 1504. The number, and/or diameters, of tubes in each section
1502
and 1504 do not have to match. For example, a larger number of tubes in
section A
1502 may be used to feed a smaller number of tubes in section B 1504 or vice-
versa.
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[0119] Similarly, an intermediate take-off 1520 after the tubing bundle
of section B
1504 diverts the steam and water to another separator 1522, which separates
the dry
steam 1524 from the condensate 1526. The condensate 1526 may then be sent to a
last section of the steam generator 1500. The separators 1514 and 1522 do not
have to
be individual.
[0120] The separators 1514, 1522, and 1530 do not have to be individual.
In some
embodiments, a single separator may be used for all of the take-off points
1512, 1520,
and 1528. If a single separator is used, internal weirs or other segmentation
devices
may be used to create compartments to separate the condensate streams,
minimizing
the mixture of condensate having different levels of contaminates. One or more
pumps
may be used to boost the pressure of the condensate 1518 or 1526 that is
returned to
the steam generator 1500.
[0121] The water quality will be poorest in the last section, and thus
the risk of scale
deposition will be greatest at that point. Accordingly, two "third sections,"
for example,
section C 1506 and C' 1508, can be included in the design to help with the
increased
risk from scale. The use of two final sections 1506 and 1508 allows the
diversion of the
condensate 1526 and any hot gases into the replacement section while the tubes
are
being replaced in an off-line third section. This allows the steam generator
1500 to
increase steam quality over a single section, as the steam generator 1500 can
be
operated much closer to the contaminant solubility limit without the fear of
having to
shutdown the entire unit in case a tube failure occurs. Thus, the condensate
1526 may
be sent to either section C 1506 or section C 1508, depending on which is
operational
at the time. In some embodiments, both sections 1506 and 1508 may be operated
together to increase the overall yield of the steam generator 1500. Further,
the extra
section may be shared with an adjacent steam generator to provide a spare for
two
steam generators with lower capital costs.
[0122] As shown, the intermediate take-offs 1512 and 1520 along the
boiler tubes
preferentially remove the steam to allow the condensate 1518 and 1526 to
continue
within the steam generator 1500. For example, if an intermediate take-off was
located
at the point where the steam quality was predicted to first achieve 55 (Yo,
and a second
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intermediate take-off was located where the steam quality was predicted to
achieve
55 % for a second time, and the final steam quality existing the steam
generator 1500
was also 55 %, the overall steam quality created by the steam generator 1500
would be
¨90 %, or around 10 % greater than may be generated without the intermediate
takeoffs. However, it can be noted that the steam quality produced in each
section may
or may not be the same.
[0123] The wet steam 1528 from section C 1506 and section C' 1508 is
sent to a
final separator 1530, which separates the dry steam 1532 from the condensate
1534.
The condensate 1534 may be sent to disposal or to a water treatment facility
for
recycling. If the contaminants are sufficiently low in the condensate 1534, it
may be in
returned to the inlet of the same steam generator 1500, or to the inlet of a
successive
steam generator. At least a portion of the condensate 1534 may be treated or
disposed
to control the build-up of contaminants. Further, a takeoff from the wet steam
1528 may
be used to provide a wet steam stream1538 to a development. In this case, the
condensate stream 1534 may be blended with the wet steam stream 1538 for
disposal,
since the extra contaminants will not harm the wet steam stream 1538.
[0124] The individual separated dry steam 1516, 1524, and 1532 is then
combined
into a dry steam stream 1536, which may be sent to injection wells via a
pipeline. In this
example two intermediate take-offs 1512 and 1520 are used to reset the steam
quality
in the steam generator 1500 back to zero at the beginning of each section
1502, 1504,
1506, and 1508. As a result, the peak velocities in the boiler tubes are
reduced allowing
the maximum allowable flow rate per boiler tube to be increased. The higher
condensate content in the boiler tubes also allows a higher heat flux to be
used with the
boiler tubes, thereby allowing a higher rate for the boiler feed water 1510,
increasing the
amount converted to dry steam 1536. Extra boiler feed water 1510 may be added
to
each of the individual sections 1504, 1506, or 1508, through a feed water line
1540.
This enables the modified steam generator 1500 to function in an analogous
fashion to
the steam generation systems shown in Figs. 7-14.
[0125] The configuration of the steam generator 1500 shown in Fig. 15
may have a
number of advantages over current steam generators. For example, the
sequential
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removal of steam from the tubing reduces the peak velocities, thereby
increasing the
maximum allowable flow rate per boiler tube. Further, the higher condensate
content in
each boiler tube, e.g., due to lower steam quality in the tube, allows a
higher heat flux to
be used with the boiler tubes, thereby allowing more boiler feed water to be
converted
to steam. The modified steam generator may be implemented for a wide range of
project sizes.
[0126] Tailoring steam generation to field usage
[0127] Fig. 16 is a process flow diagram of a method 1600 for tailoring
the quality of
steam production to field needs. The method 1600 may be used to improve
thermal
recovery processes for a hydrocarbon reservoir that is exploitable through
surface
mining, subsurface mining, in situ techniques, or any combinations thereof.
[0128] The method 1600 starts at block 1602 by matching thermal recovery
processes with specific reservoir regions within the development to achieve
optimal
resource recovery. To begin, the reservoirs expected to be developed over the
life of
the project are delineated. Reservoir delineation typically occurs through the
combined
use of delineation wells, remote sensing technologies such as 2D and 3D
seismic
studies, studies of modern analogs and outcrop studies of the target
reservoir, for
example, if parts of the reservoir outcrop on surface, or studies of other
reservoirs with
comparable depositional setting. Remote sensing technologies, modern analogs,
and
outcrop studies allow the prediction of the spatial distribution of the
reservoir attributes
through the reservoir.
[0129] Delineation wells are used to collect core samples of the target
reservoir and
to collect log data, both for open hole and cased hole wells. The cores may be
used to
gain an understanding of the depositional settings present in the reservoir,
porosity and
oil content distributions, horizontal and vertical permeability distributions,
oil density and
viscosity information, sand grain size analyses and reservoir rock samples
that can be
used to understand how the reservoir material will respond to heating with
steam or
water. The core samples may be used to identify the ease with which the
hydrocarbons
can be separated from the reservoir fabric during surface extraction
operations. The
delineation wells may also be used to collect data detailing the ability of
the reservoir
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caprock to withstand increases in pressure as a result of steam injection, and
the initial
pressure distribution in the reservoir. Further, they can aid the
identification of the
presence and areal extent of any pressure sinks, or intervals that may require
dewatering, such as top gas, top or bottom water. This may include
interstitial intervals
with the reservoir that have initial enhanced water mobility, present in or in
proximity to
the oil bearing sections. Further, the data may be used to identify locations
and
capacities, of water make-up sources and water disposal intervals.
[0130] The data can be used to create a geologic model for each
reservoir that is
expected to be developed as part of the overall development. These geologic
models
can be constructed using a geologic modeling software program. The available
open
hole and cased hole log, core, 2D and 3D seismic data, and knowledge of the
depositional environment setting may be used in the construction the geologic
model.
[0131] The attributes of various recovery processes can be used to
interrogate the
geologic models to identify the areas of the reservoirs that have attributes
amendable to
the various recovery processes. For example, a recovery process that relies on
the
ability to cycle pressures, such as CSS, would not be a preferred recovery
process
when developing a portion of a reservoir where an extensive top gas interval
is present.
Further, a surface mining process would not work for a deep reservoir.
[0132] At block 1604 the overall depletion strategy is designed to
optimize the field
design, steam generation and water treatment facilities for the entire life of
the recovery
project. For each combination of reservoir description and recovery
technology, a
series of performance predictions can be made using a reservoir simulation
program, or
a mine planning program. It may also be possible to use simple empirical or
analog
based models for performance prediction.
[0133] In many cases, follow-up recovery processes can be used to further
enhance
the recovery of the hydrocarbon. These options to extend recovery can be
considered
during the planning phase to assist in determining designs for resources.
[0134] A combination of simple economic models, performance expectations
for a
recovery process, and field layout and infrastructure considerations can be
used to
optimize the overall sequence for the development. This knowledge may then be
used
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to identify the remaining acquisition requirements for reservoir data and the
timing of
their capture.
[0135] As further data is acquired, the geologic models will continue to
evolve over
time. Once the geologic models have demonstrated the capability to reasonably
predict
the results for a planned recovery technology, for example, as observed in
recently
drilled delineation wells, the geologic data collected may be considered
sufficient. In
addition, a commercial thermal development may typically have an operating
life of 20 ¨
50+ years. Thus, the existing thermal recovery processes may continue to
evolve and
new thermal recovery processes will continue to develop. Accordingly, the
steam
generation facility can be designed to respond to future shifts in steam
quality used by
the development.
[0136] At block 1606, the factors are identified that indicate the time
to convert to a
different steam quality to support a different mix of recovery processes. To
this point in
the development planning process, the actual design of the steam generation
facilities is
not considered, other than keeping the design flexible with regard to steam
quality. For
example, it may be useful for a steam generation facility to initially
generate only wet
steam and then, over time, see a need to generate progressively larger
fractions of dry
steam ending with a need for only dry steam. Similarly, it may be useful to
switch back
and forth between generating primarily wet steam to primarily dry steam
multiple times
over the life of the development.
[0137] At block 1608, the steam generation facility is installed during
development of
the field. The wells are completed to the reservoir, and any surface mining
processes
are started. The initial thermal recovery processes that use the wells, such
as CSS,
may be started at this point. To illustrate the process, various thermal
recovery
processes are described herein. However, embodiments are not limited to the
processes described, but may be used with any thermal recovery process. The
steam
used for the initial thermal recovery processes may be wet, as discussed
above.
[0138] As production from the CSS falls, a portion of the wells may be
converted to
steam flood. Further, other wells may be drilled in the reservoir to begin
SAGD
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recovery processes in other regions. Primary SAGD processes are known to be
more
effective when dry steam is used.
[0139] At block 1610, the steam generation facility is transitioned from
producing
mostly or all wet steam to producing some amount of dry steam, for example, by
converting a first steam system to dry steam production. For a development
scenario
where a newly started thermal recovery process requires dry steam, wet steam
can also
be generated, for example, using parallel or adjacent steam systems as
described
herein.
[0140] In an embodiment, at the exit of a first steam system, the steam
and
condensate can be separated with the condensate being directed to the inlet of
an
adjacent steam system where it is used as a part of the feed water. At the
exit of the
second steam system, the steam and condensate can be separated with the
condensate being directed to the inlet of the adjacent steam system where it
is used as
a part of the boiler feed water stream. The cascading may be continued across
as
many multiple steam systems to meet the demand for wet steam versus dry steam.
[0141] This cascading of condensate between parallel steam systems so
arranged
allows a higher overall steam quality to be generated, as measured per unit of
boiler
feed water. The improvement in steam quality is irrespective of the number of
steam
systems being used in the development. In addition, if one of the parallel
steam
systems is down for repair, the condensate can be cascaded to the next
available
steam system, thus, maintaining the expected benefits.
[0142] At block 1612, the water reuse is balanced against the steam
generation
quality. As discussed, the concentration of contaminants present in the boiler
feed
water will increase in a predictable fashion along a row of cascaded steam
systems.
For example, if the steam quality generated is 80 % in each steam system, the
sequential blending of the condensate with the boiler feed water will cause
the
contaminant loading to increase by 80 % with each incremental cascading of the
condensate.
[0143] If the contaminant loading at the exit of the last steam system
in the cascade
is predicted to be less than the solubility limit, the opportunity exists to
reduce the level
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of the boiler water treatment, saving operating costs, and potentially
capital. However, if
the contaminant loading at the exit of the last parallel steam generator is
predicted to be
above the solubility limit, then the steam quality generated in the last
parallel steam
generators can be reduced to maintain solubility. Further, if the contaminant
loading at
the exit of the last parallel steam system is predicted to be above the
solubility limit,
then the steam systems can be formed from parallel groups of two or more steam
generators, with the condensate cascaded between these steam systems. The
number
of generators per steam system can be chosen to ensure that solubility is
maintained in
the last group of generators.
[0144] The processing of the condensate from the last steam system in the
cascade
may be determined by a number of factors. These may include the ability of the
condensate to keep the contaminants dissolved at the temperatures expected in
the
disposal process or formation. If the potential for further concentration of
the
condensate exists, the condensate can be dropped to a lower pressure which
will allow
a portion of the water to flash to steam. This steam can then be used as a
heat source
within the plant or condensed and utilized as a make-up water source. Further,
if water
is in short supply, the condensate may be passed to a water treatment facility
to remove
a portion of the contaminants.
[0145] As described, the cascading of condensate between steam systems may
result in each steam system operating at a progressively lower pressure. The
hot
condensate can be mixed with current boiler feed water stream downstream of
the high
pressure pump to ensure flashing does not occur in the next steam system. As a
result,
the cooler temperatures can lower the pressure. If it is desired to have all
of the parallel
steam systems operating at the same pressure, or to have the later steam
systems in
the cascading arrangement operate at a higher pressure than the earlier steam
system,
pumps can be used to boost the pressure of the condensate cascaded between the
operated in parallel steam generators.
[0146] Continuing with this example, as development activities evolve in
this
scenario and wet steam demand occurs, for example, due to development in new
areas
of the field, the last steam generator in the cascading arrangement can be
returned to
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wet steam service by bypassing the separation step at the exit of the steam
system. If
the demand for wet steam increases further, additional steam generators near
the end
of the cascading arrangement can be converted to wet steam service.
Conversely, if
the short or long term demand for dry steam were to increase, starting with
the most
.. recently converted wet steam generator, the steam generators can be easily
converted
back to dry steam service by completing the separation step at the exit of the
generator.
[0147] The techniques described herein may be applied to new thermal
development
schemes or expansions to existing thermal development schemes. They may also
be
retrofitted into existing thermal based development schemes. The thermal
recovery
processes can include surface mining, subsurface mining, such as slurrified
production
of oil sands, and in situ opportunities, such as CSS, steam flood, SAGD, and
the like.
The conversion of a facility initially designed to generate wet steam to one
capable of
generating dry steam, using the technique by cascading the condensate between
parallel steam system frees boiler feed water treating capacity. If the
development plan
.. confirms that sufficient surplus boiler feed water treating capacity will
be available for a
sustained period of time, a new steam system, such as a single OTSG or HRSG,
can
be installed to generate additional steam using the now idle boiler feed water
treatment
capacity. By applying the strategies outlined herein, this opportunity can be
identified
early and, thus, plot space could be left to allow for the future installation
of this new
steam system.
[0148] For both new development schemes and expansions to existing
development
schemes, a novel configuration is available once it is recognized that two
design
constraints in OTSG or HRSG design are the exit velocity of the fluids and the
heat flux
along the tubing. To decrease erosion, the maximum quantity of water fed into
each
boiler tube can be constrained such that the maximum velocity constraint is
not
exceeded at the exit of the boiler tubes. To help prevent localized dry out
conditions,
and scale deposition in the boiler tubes, the maximum heat flux can also be
constrained, especially where it is anticipated that the steam quality in the
boiler tube
will be higher.
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[0149] By following the method for improving thermal recovery processes
from a
subsurface hydrocarbon reservoir described herein, either the cascading steam
generation design, or the internally segmented steam generator design, or a
combination of both, may provided the desired flexibility to meet both short
and long
term shifts in the demand for wet and dry steam. For example, Figs. 17-19 show
examples of developments that can take advantage of the steam systems
discussed
herein. Although a particular steam system is shown for all three figures,
corresponding
to the system of Fig. 10, it can be noted that any of the systems in Figs. 7-
15 could be
used to supply steam for the developments.
[0150] Fig. 17 is a drawing of a development 1700 for which dry steam is
separated
from the wet steam and the different steam lines are directed to regions of
the field
where recovery processes efficiently use the wet or dry steam. Like numbered
items
are as discussed with respect to the prior figures. Although the steam system
shown in
Figs. 17-19 is essentially the system 1000 discussed with respect to Fig. 10,
it can be
understood that any of the systems discussed with respect to Figs. 7-15 may be
used.
In this application, the dry steam 402 is supplied to the injection well 1702
of a SAGD
pair. Hydrocarbons may then be harvested from the collection or production
well 1704.
The wet steam 302 from the steam generators 206 may be directly supplied to a
series
of steamflood wells 1706. The condensate 406 from the separator (or any
comparable
condensate stream in Figs. 7-15) can be added to the wet steam 302 to reduce
contaminates.
[0151] Fig. 18 is a diagram of a SAGD process 1800 with infill wells
1802 where the
efficiency of the process is enhanced by directing dry steam to the SAGD
injection wells
1804 and wet steam to the infill well injectors. As for the development 1700
of Fig. 17,
the SAGD process 1800 may allow any excess condensate 406 to be blended with
the
wet steam 302 for injection into the reservoir 1806.
[0152] Fig. 19 is a drawing of configurations that may be used for the
co-injection of
solvent and steam. In these configurations, the solvent may be heated heat
exchanging
with the wet steam 302, as indicated by heat exchangers 1902 and 1904. The
heat
exchange may vaporize the solvent before it is injected into the dry steam
402, and
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injected with the dry steam 402 into the SAGD injection wells 1906. The wet
steam 302
may be injected into infill wells 1908, with or without mixing in excess
condensate 406.
Although the solvent may be injected without the heating, the energy used to
vaporize
the solvent will cause a fraction of the steam to condense in the dry steam
402, lowering
the efficiency of the process. If more heat is needed, for example, to
decrease the
amount of condensation in the wet steam, the solvent may be preheated by heat
exchanging with the feed water stream 202, for example, using another heat
exchanger
1910.
[0153] The above-described embodiments of the invention are intended to
be
examples only. Alterations, modifications, and variations can be effected to
the
particular embodiments by those of ordinary skill in the art without departing
from the
scope of the invention, which is defined solely by the claims appended hereto.
EXEMPLARY EMBODIMENTS
[0154] An exemplary embodiment provides a steam system. The steam system
includes a steam generator that includes boiler tubes that are modified to
form a
number of intermediate take-offs for removing water and steam from the boiler
tubes. A
number of intermediate separators are used to separate the water and steam at
each of
the number of intermediate take-offs A number of intermediate couplings are
used to
inject the water back into the boiler tubes downstream of each of the
plurality of
intermediate take-offs.
[0155] In some embodiments, the intermediate separators include
condensate
reservoirs in a single vessel. Each of the condensate reservoirs is separated
from other
condensate reservoirs by a weir.
[0156] In some embodiments, the system includes a hydrocarbon development
using at least one thermal recovery process. The thermal recovery process is
configured to utilize the steam produced by the steam generator.
[0157] The steam generator can be configured to provide wet steam, dry
steam, or a
combination thereof. In some embodiments, the system includes a number of
thermal
recovery processes, wherein at least a portion of the thermal recovery
processes utilize
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wet steam provided by the steam generator and at least a portion of the
thermal
recovery processes utilize dry steam provided by the steam generator.
[0158] In some embodiments, the number of boiler tubes used downstream
of each
of the plurality of intermediate take-offs is the same as the number of boiler
tubes used
upstream of each of the plurality of intermediate take-offs. In some
embodiments, the
number of boiler tubes used downstream of each of the plurality of
intermediate take-
offs is less than the number of boiler tubes used upstream of each of the
plurality of
intermediate take-offs.
[0159] In some embodiments, the system includes at least one
intermediate
separator that includes a gravity separator. In some embodiments, the system
at least
one intermediate separator that included a centrifugal separator.
[0160] In some embodiments, a section of boiler tubes beyond the last of
the
plurality of intermediate take-offs is duplicated to provide a spare section
of boiler tubes.
In some embodiments, the duplicated section of boiler tubes is shared by
adjacent
steam generators.
[0161] Another exemplary embodiment provides a method for improving
recovery
from a hydrocarbon reservoir. The method includes matching a steam quality to
a
hydrocarbon development, wherein the steam is generated by a steam generator.
The
steam generator includes boiler tubes that are modified to form a number of
intermediate take-offs for removing water and steam from the boiler tubes. A
number of
intermediate separators separate the water and steam at each of the
intermediate take-
offs. A number of intermediate couplings inject the water back into the boiler
tubes
downstream of each of the plurality of intermediate take-offs. The steam
generator is
adapted to match a change in steam usage caused by a change in the hydrocarbon
development.
[0162] In some embodiments, the method includes blending the water
removed from
at least one intermediate take-off with a boiler feed water stream to form a
blended
stream. The blended stream is injected back into the boiler tubes downstream
of the
intermediate take-off from which the water was removed.
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[0163] In some embodiments, the method includes performing a plurality
of thermal
recovery processes on regions within the hydrocarbon reservoir. Different
recovery
processes are used for different regions or at different times.
[0164] In some embodiments, the method includes performing a thermal
recovery
process comprising steam assisted gravity drainage (SAGD), cyclic steam
stimulation
(CSS), a steam flood process, a warm water extraction process, a Clark hot
water
extraction process, or any combinations thereof.
[0165] In some embodiments, the method includes subdividing the boiler
tubes by
separating each individual boiler tube. In some embodiments, the method
includes
subdividing the boiler tubes by separating all the boiler tubes in a common
separation
system. In some embodiments, the method includes subdividing the boiler tubes
by
separating a fraction of the boiler tubes as a single entity.
[0166] In some embodiments, the method includes drilling a plurality of
infill steam
injection wells between each of a number of steam assisted gravity drainage
(SAGD)
wellpairs. Dry steam is injected into the steam injection wells of the SAGD
well pairs
and wet steam is injected into the plurality of infill steam injection wells.
[0167] In some embodiments, the method includes injecting dry steam into
steam
injection wells in a number of steam assisted gravity drainage (SAGD)
wellpairs and
injecting wet steam into a number of steam flood wells.
39
